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IOR 2009 - 15th European Symposium on Improved Oil Recovery
- Conference date: 27 Apr 2009 - 29 Apr 2009
- Location: Paris, France
- ISBN: 978-90-73781-60-3
- Published: 27 April 2009
21 - 40 of 64 results
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Experimental and Numerical Modeling Studies of Viscous Unstable Displacement
Authors A. Skauge, K. Sorbie, P. A. Ormehaug and T. SkaugeExperimental studies of fluid flow at adverse mobility ratio have quantified the development of viscous
fingers. CIPR have developed an experimental set up for 2-D in-situ saturation measurements. The X-ray
scanner can quantify saturations over a large 2-D area and can also image saturation changes of up to 1 x 1
m rock slabs. The 2-D scanner is designed specifically to study viscous unstable displacements for both
miscible and immiscible processes.
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Experimental Investigation of Effect of Depletion Rates on Recovery of a Heavy Oil Reservoir
Authors S. A. Mirhaj, M. Fazaelizadeh, P. L. J. Zitha and R. KharratHeavy-oil reservoirs in western Canada and Venezuela show high primary recovery under solution gas
drive mechanism. Pressure decline rate in these reservoirs is low compared to that expected under solution
gas drive in conventional oil reservoirs due to high viscosity. Several studies have been reported a
dramatic effect of depletion rate on performance of solution gas drive in heavy oil system.
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Selection of a New IOR/EOR Strategy for the Heavy Oil Brown Field in Kazakhstan
Authors A. A. Mosesyan, S. A. Nagorniy, E. A. Chernitsyna and Y. A. TrotsenkoThe World experience proved that heavy oil fileds potential is highly dependent on the proper IOR/EOR
strategy assigned for the field from the first days of development. This crucial goal becomes additionally
complicated when you're handling brown field and are limited in choice of methods.
So, the development of IOR/EOR strategy for a heavy oil brown field becomes a serious challenge,
especially if the current status of the field development demonstrates the ineffectiveness of the initially
applied production methods.
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Miscible Carbon Dioxide Flood Imaging – Analysis of 4D Seismic Wavelet Transform Spectral Composites
Authors A. E. Raef, L. W. Watney and A. P. ByrnesSubtlety of 4D seismic anomalies, in carbonates, call upon using high-resolution seismic, which require
very demanding tighter cross-equalization standards. We present a non-equalization approach utilizing
wavelet transform (WT) spectral components of time-frequency-amplitude analysis of 4D seismic data for
both, imaging EOR/sequestration Carbon Dioxide flood in a thin (3-5 m thick) Upper Pennsylvanian
oomoldic carbonate reservoir in central Kansas-USA, and for helping to identify fluid-flow controls.
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Direct Observation of CO2 Transport and Oil Displacement Mechanisms in CO2/Water/Oil Systems
Authors M. Riazi, M. Riazi, M. Jamiolahmady, S. Ireland and C. BrownAs the concern over the greenhouse gas effects of carbon dioxide (CO2) increases, its injection into oil and
gas reservoirs for enhancing hydrocarbon recovery and in saline aquifers for storage is on the rise.
Variation of reservoir pressure and temperature affects the properties of CO2 and its interaction with
reservoirs resident phases. Although in most cases CO2 would be in supercritical state at reservoir
conditions, however, it is necessary to understand the flow and displacement mechanisms of CO2/water/
oil systems in porous media under various reservoir conditions.
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Modelling of CO2 Injection
Authors L. Surguchev and G. CalderonThis paper presents results of secondary CO2 and CO2-rich gas injection experiments and simulations.
Displacements were performed in Berea cores under viscous dominated flow regime in order to evaluate
viscous effects at CO2 injection. The formation of three hydrocarbon phases under CO2 flood and its
effect on oil recovery have been already investigated in some core flood experiments. Few experimental
evaluations of CO2-rich phase injection effects have been performed at high pressure and above CO2
critical temperature. Immiscible CO2 injection was performed in high and low viscosity oil saturated
cores. Later gas breakthrough and higher oil production were observed at lower oil viscosity experiments.
The ultimate oil recoveries for low and high viscosity oils were very close at continuous CO2 injection. In
the floods with CO2-rich phase the achieved oil recovery could be correlated with CO2-rich phase
volume. Total oil recovery increases as the CO2-rich phase volume increases and miscible displacement
develops. Due to oil vaporisation and stripping by the moving CO2 tail-front significant amounts of oil
can be produced after the breakthrough of CO2. Representative simulation of CO2 injection requires
accurate modelling of viscous effects and formation of CO2-rich phase.
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Three–Phase Flash in Compositional Simulation Using a Reduced Method
Authors R. Okuno, R. T. Johns and K. SepehrnooriCO2 flooding at low temperatures often results in three or more hydrocarbon-phases. Multiphase
compositional simulation must accurately simulate such gas floods. Drawbacks of modeling three
hydrocarbon-phases are the increased computational time and convergence problems associated with flash
calculations. Use of a reduced method is a potential solution.
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Fractional-Flow Theory of CO2 Foam Displacements with Surfactant Dissolved in the CO2
Authors E. Ashoori, T. L. M. van der Heijden and W. R. RossenA foam process with surfactant dissolved in supercritical CO2 has the advantage that injection of CO2,
once begun, need never be interrupted for surfactant injection in water. In addition, CO2 can carry
surfactant to layers that may not be swept by an aqueous surfactant slug. CO2 carries the surfactant and
forms foam with water in the formation.
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Asphaltene Deposition during CO2 Injection in an Iranian Carbonate Reservoir – An Experimental and Simulation Approach
Authors S. H. Mirhaj and S. A. MirhajIn a CO2 miscible displacement process, the injected CO2 solvent can induce flocculation and deposition
of asphaltenes and other heavy organic particles. This can cause numerous production problems with a
detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic
matter under reservoir operating conditions.
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A New CO2 EOR Predictive Correlation
Authors J. Brodie, B. Jhaveri and D. PuckettMiscible CO2 flooding is a well-established method for enhancing oil recovery and is the subject of
renewed interest as an option to control emissions of greenhouse gases. There is a requirement for rapid
screening of reservoirs for CO2 flooding prior to undertaking detailed, resource-intensive studies. In this
paper, we describe a new CO2 EOR predictive correlation that has been developed to screen tertiary CO2
floods in sandstone reservoirs. The new correlation was developed by fitting a response surface model to
a large simulation database. The simulation data were generated by varying key reservoir and fluid
properties in a fully compositional finite difference model. The new correlation has been validated against
additional simulation cases and historic CO2 floods in sandstone reservoirs and can be applied to cases
where existing models (e.g. Claridge, 1972) give inaccurate results. The new correlation is recommended
for high-level screening of CO2 EOR.
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Simulation Aspects of the CO2 EOR Including Foam
Authors R. A. Berenblyum, J. F. Zuta, I. Fjelde and L. M. SurguchevThis paper addresses simulation aspects of the CO2 injection into the porous media. The presented results
are based on the mechanistic and laboratory scale simulations. These findings would lay out the basis for
the field scale CO2 injection pilot.
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CO2-Foam Processes in a Fractured Chalk Model
More LessThe injection of CO2 with a suitable aqueous solution of a CO2-foaming agent into a reservoir formation
has been shown to improve on CO2 mobility and increase macroscopic sweep efficiency. However, during
CO2-foam flooding in fractured chalk reservoirs with low matrix permeability compared to fracture
permeability, the solutions will mainly be transported through the fracture network. At higher matrix
permeability, viscous flooding of the matrix will also be important. Foam in fractures can divert more of
the CO2 and surfactant solution to the matrix.
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Correlation between SAGD Steam Chamber Growth and Geological Heterogeneity
Authors I. D. Gates and D. GotawalaEvolution of Steam Assisted Gravity Drainage (SAGD) steam chambers in heavy oil and bitumen
reservoirs is tied to: 1. uniformity of steam pressure and quality along the length of the perforated interval
of the well and 2. reservoir geology and fluid properties adjacent to the well. If steam delivery into the
injection well is not uniform, then non-uniform steam is delivered to the reservoir along the wellpair. If
the reservoir geology has poor permeability at an interval along the wellpair, then steam delivery to and
fluids production from the reservoir is not uniform. If the steam is well distributed throughout the
injection well, then the key factor for a uniform steam chamber along the wellpair is reservoir geology.
This is especially important in highly heterogeneous, variable thickness reservoirs where geology and
reservoir oil composition may vary significantly over the length of a wellpair. In this study, heterogeneity
of a growing SAGD steam chamber is related to heterogeneity of the underlying geology. Here, the oil
sand models are geostatistically populated to model heterogeneity of porosity and permeability.
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Regularities of Alternated Displacement of High-Viscosity Oil by Steam and Surfactant-Based Systems, Generating CO2 in s
Authors L. K. Altunina, V. A. Kuvshinov and I. V. KuvshinovA complex EOR technology has been developed at the Institute of Petroleum Chemistry SB RAS to
increase the efficiency of thermal-steam and cyclic-steam treatments of high-viscosity oil pools by
surfactant-based systems capable to generate СО2 and alkaline buffer solutions in situ. Presented are the
results of laboratory research on the effect of the concentration of oil displacing systems and slug volumes
on oil displacement factor under the conditions simulating thermal-steam and cyclic-steam treatments. It
has been determined that alternation of steam slugs and oil displacing system allows one to obtain higher
values of oil displacement factor as compared to thermal-steam treatment. The injection of the first system
slug provides the major contribution to the increase in oil displacement factor. Generalizing dependencies
of oil displacement factor on the accumulated volume of the system injection were deduced. Under field
conditions it is recommended to use surfactant-based systems at concentration of 50 %. Computer
programs were developed to calculate the volumes of oil displacing systems at planning pilot tests. In
2002-2008 pilot tests of the complex technology were carried out in oil fields of Russia and China to
enhance oil recovery from high-viscosity oil pools. The results of the tests are presented.
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4D Seismic Modelling Applied to SAGD Process Monitoring
Authors O. Lerat, F. Adjemian, A. Auvinet, A. Baroni, E. Bemer, R. Eschard, G. Etienne, G. Renard, G. Servant, S. Rodriguez, E. Bathellier and E. ForguesThe performance of heavy-oil production by Steam-Assisted Gravity Drainage process (SAGD) can be
affected by near-well reservoir heterogeneities. However, as many factors interact during thermal
production such as changes in oil viscosity, fluid saturations, pore pressure, stresses,... the interpretation of
4D seismic data in terms of steam chamber geometry is not direct nor unique.
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Optimization of Solvent – Based Enhancements of Steam Assisted Gravity Drainage
Authors T. Ibatullin and A. B. ZolotukhinModern Steam Assisted Gravity Drainage (SAGD) technology has proven its efficiency throughout the
world. However, sometimes steam generation by natural gas combustion can render the process
uneconomic. Moreover, ever-increasing environmental concerns and green house gases emission s
restrictions require further improvement of the existing technology. In addition to overcoming
environmental issues, operators are also interested in improving SAGD s performance in terms of daily
rates and recovery factors.
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Experimental and Numerical Analysis of In Situ Combustion in Fractured Carbonates
Authors H. Fadaei, A. Kamp, G. Debenest, L. Castanier and M. QuintardApproximately one third of global heavy oil resources can be found in fractured reservoirs. In spite of its
strategic importance, recovery of heavy crudes from fractured reservoirs has found few applications due to
the complexity of such reservoirs. In situ combustion is a candidate process for such reservoirs, and
especially for those where steam injection is not feasible. Experimental studies reported in the literature on
this topic mentioned a cone-shape combustion front, indicating that the process was governed by diffusion
of oxygen into the matrix. The main oil production mechanisms were found to be thermal expansion of oil
and evaporation of light components.
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Automated History Matching of Combustion Experiments Using the Ensemble Kalman Filter
In-situ combustion (ISC) and High Pressure Air Injection (HPAI) are enhanced oil recovery processes, in
which air or oxygen enriched air is injected into a reservoir. The oxygen present in the air reacts with the
crude oil in the reservoir. This results in a combustion front propagating through the reservoir, generating
heat and flue gases. Many chemical reactions take place over different zones and temperature ranges
during the process. Reaction schemes based on pseudo components are used in numerical simulations to
describe these reaction processes. The kinetics of these reactions are given by Arrhenius-type equations.
A still remaining challenge in combustion modelling is the estimation of the Arrhenius kinetic parameters.
Combustion tube experiments are therefore performed to obtain information about the burn characteristics
that depend on the crude and reservoir rock properties. The Arrhenius parameters can be estimated by
history matching these experiments. The obtained values have to be up-scaled before they can be used for
field-scale simulations. History matching the combustion tube experiments is an intensive and timeconsuming
process, because multiple reactions occur at the same time and because non-unique matches
are expected. An automated history-matching tool for combustion tube tests is desired to quantify
uncertainty in the obtained kinetic parameters and reduce time spend to obtain a good match. In this work
a method is described for the automated history matching of combustion tube experiments using the
Ensemble Kalman Filter (EnKF).
The Ensemble Kalman Filter is a sequential data assimilation technique that combines measurement series
with dynamic models. The EnKF uses a Monte Carlo approach in which model errors are represented by
an ensemble of realizations. The ensemble is integrated in time to make predictions on system parameters
and state variables and their uncertainties.
The method to history match combustion tube experiments using the Ensemble Kalman Filter is described
in this paper and applied to combustion tube experiments. The matching of the combustion tube test is
based on temperature profiles, oil and water production data and effluent composition. It is shown how the
initial uncertainty in the kinetic parameter ranges (activation energy and frequency factor) are reduced by
automated history matching of the experiments, using the EnKF method.
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Analytical Study of In-situ Combustion in a Wet Porous Medium
Authors G. Chapiro, A. A. Mailybaev, H. Bruining and D. MarchesinThere is a renewed interest in using combustion for the recovery of medium viscosity oil. In-situ
combustion is commonly divided into zones according to the main processes occurring inside.
In the downstream order they are combustion, coke, cracking, steam and light hydro-carbon zones. In this
analytical study the cracking reaction and the light hydro-carbon vaporization process are neglected for
simplicity. We take into account the reaction occurring between the residual petroleum coke and the
oxygen contained in the injected air. We also assume the presence of small amount of immobile liquid
phase, which can vaporize; this feature is useful if this study is applied to gasefication of coal
containing water.
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“Smart Water” as Wettability Modifier in Carbonate and Sandstone
Authors S. Strand, A. R. Doust, T. P. Puntervold and T. A. AustadWaterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years,
extensive research on crude oil, brine, rock (COBR) systems has documented that the composition of the
injected water can change wetting properties of the reservoir during a waterflood in a favorable way to
improve oil recovery. Thus, injection of Smart Water with a correct composition and salinity can act as a
tertiary recovery method. Economically, it is, however, important to perform a water flood at an optimum
condition in a secondary process. Examples of Smart Water injection in carbonates and sandstones are:
Injection of seawater into high temperature chalk reservoirs
Low Salinity floods in sandstone reservoirs
The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic
for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for
the wettability modification in the two types of reservoir rocks are shortly reviewed with a special focus on
possible chemical similarities. The different chemical bonding mechanisms of polar components from the
crude oil onto the positively charged carbonate and the negatively charged quartz/clay indicates a different
chemical mechanism for wettability modification by Smart Water in the two cases.
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